Gas assisted downhole pump

ABSTRACT

An artificial lift system is disclosed for removing wellbore fluids from directional or horizontal wellbores. The artificial lift system incorporates a dual tubing arrangement in which each string contains (respectively) a downhole pumping system or a gas lift system. In one string, a gas lift system, preferably intermittent, is utilized to lift reservoir fluids from below a packer assembly to above a packer assembly. This same tubing string is sealingly engaged to the packer and also contains a concentric inner tubing string which extends through and below the packer into the deviated well bore section. This concentric tubing arrangement provides a conduit for the injection gas and also a conduit for the return of commingled reservoir fluids and injection gas where the commingled fluids exit into the annular void between the dual tubing arrangement and the casing, located above the packer. The second tubing string, which is not sealingly engaged to the packer, contains a downhole pump placed above the exit point of the commingled fluids into the annulus. Because these liquids are trapped above the packer, each time the gas lift system cycles, they accumulate over time and rise above the downhole pump, which pumps the liquids to the surface. In an alternate embodiment of the invention, a plurality of tubing string arrangements are utilized A plurality of tubing string arrangements are sealingly engaged to a packer and operatively connected to a concentric tubing string that extends into the deviated section of the wellbore. A gas lift system, preferably intermittent, is utilized to lift reservoir fluids from below the packer to above the packer. This concentric tubing arrangement provides a conduit for the injection gas and also a conduit for the return of commingled reservoir fluids and injection gas. The commingled fluids exit through a perforated sub in one of the tubing strings above the packer and enter into the annular void between the dual tubing arrangement and the casing. A standing valve is located in the second tubing string below the perforated sub, which effectively trap the liquids in the annulus above the packer. Each time the gas lift system cycles, these liquids accumulate over time and rise above the downhole pump, which pumps the liquids to the surface.

BACKGROUND OF THE INVENTION

I. Field of the Invention

The present invention relates to artificial lift production systems and methods deployed in subterranean oil and gas wells, and more particularly relates to artificial lift production systems and methods for removing wellbore liquids from directional or horizontal wellbores.

II. Background and Prior Art

Many oil and gas wells will experience liquid loading at some point in their productive lives due to the reservoir's inability to provide sufficient energy to carry wellbore liquids to the surface. The liquids that accumulate in the wellbore may cause the well to cease flowing or flow at a reduced rate. To increase or re-establish the production, operators place the well on artificial lift, which is defined as a method of removing wellbore liquids to the surface by applying a form of energy into the wellbore. Currently, the most common artificial lift systems in the oil and gas industry are down-hole pumping systems and compressed gas systems.

The most popular form of down-hole pump is the sucker rod pump. It comprises a dual ball and seat assembly, and a pump barrel containing a plunger. The plunger is lowered into a well by a string of rods contained inside a production tubing string. A pump jack at the surface provides the reciprocating motion to the rods which in turn provides the reciprocal motion to stroke the pump. As the pump strokes, fluids above the pump are gravity fed into the pump chamber and are then pumped up the production tubing and out of the wellbore to the surface facilities. The invention will also function with other downhole pump systems such as progressive cavity, jet, electric submersible pumps and others.

Compressed gas systems can be either continuous or intermittent. As their names imply, continuous systems continuously inject gas into the wellbore and intermittent systems inject gas intermittently. In both systems, compressed gas flows into the casing-tubing annulus of the well and travels down the wellbore to a gas lift valve contained in the tubing string. If the gas pressure in the casing-tubing annulus is sufficiently high compared to the pressure inside the tubing adjacent to the valve, the gas lift valve will be in the open position which subsequently allows gas in the casing-tubing annulus to enter the tubing and thus lift liquids in the tubing out of the wellbore. Continuous gas lift systems work effectively unless the reservoir has a depletion or partial depletion drive. Depletion or partial depletion drive reservoirs undergo a pressure decline as reservoir fluids are removed. When the reservoir pressure depletes to a point that the gas lift pressure causes significant back pressure on the reservoir, continuous gas lift systems become inefficient and the flow rate from the well is reduced until it is uneconomic to operate the system. Intermittent gas lift systems apply this back pressure intermittently and therefore can operate economically for longer periods of time than continuous systems. Intermittent systems are not as common as continuous systems because of the difficulties and expense of operating surface equipment on an intermittent basis.

Horizontal drilling was developed to access irregular fossil energy deposits in order to enhance recovery of hydrocarbons. Directional drilling was developed to access fossil energy deposits some distance from the surface location of the wellbore. Generally, both of these drilling methods begin with a vertical hole or well. At a certain point in this vertical well, a turn of the drilling tool is initiated which eventually brings the drilling tool into a deviated position with respect to the vertical position.

It is not practical to install most artificial lift systems in the deviated sections of directional or horizontal wells since down-hole equipment installed in these regions can undergo high maintenance costs. Therefore, most operators only install down-hole artificial lift equipment in the vertical portion of the wellbore. However, downhole pump systems and compressed gas lift systems are not designed to recover any liquids that exist below the down-hole equipment. In many directional and horizontal wells, a column of liquid ranging from 300 to many thousands of feet may exist below the down-hole equipment installed in the vertical portion of the wellbore. Because of this condition considerable hydrocarbons reserves cannot be recovered using conventional methods in depletion or partial depletion drive directional or horizontally drilled wells. Thus, a major problem with the current technology is that reservoir liquids located below conventional down-hole artificial lift equipment cannot be lifted.

Therefore, one object of the present invention is to provide an artificial lift system that will enable the recovery of liquids in the deviated sections of directional or horizontal wellbores.

It is also an object of the present invention to lower the artificial lift point from the vertical wellbore section into the deviated section.

It is also an object of the present invention to provide a high velocity volume of injection gas to more efficiently sweep the reservoir liquids from the wellbore.

A further object of the present invention is to provide a more efficient, less costly wellbore liquid removal process.

These and other objects of the present invention will become better understood with reference to the following specification and claims.

SUMMARY OF THE INVENTION

A gas assisted downhole pump is disclosed, which is an artificial lift system designed to recover by-passed hydrocarbons in directional and horizontal wellbores by incorporating a dual tubing arrangement in which each string contains (respectively) a downhole pumping system or a gas lift system. In one string, a gas lift system (preferably intermittent) is utilized to lift reservoir fluids below the downhole pump to above a packer assembly where the fluids become trapped. As more reservoir fluids are added above the packer, the fluid level rises in the casing annulus above the downhole pump (which is installed in the adjacent string), and the trapped reservoir fluids are pumped to the surface by the downhole pump.

BRIEF DESCRIPTION OF THE DRAWINGS

For a further understanding of the nature and objects of the present invention, reference is had to the following figures in which like parts are given like reference numerals and wherein:

FIG. 1 depicts a directional or horizontal wellbore installed with a conventional rod pumping system of the prior art:

FIG. 2 depicts a conventional gas lift system in a directional or horizontal wellbore of the prior art;

FIG. 3 depicts one version of the invention utilizing a rod pump and a gas lift system;

FIG. 4 depicts another embodiment of the invention similar to FIG. 3;

FIG. 5 depicts yet another embodiment of the invention similar to the FIG. 3, but with a different downhole configuration; and

FIG. 6 depicts another embodiment of the invention similar to FIG. 5.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

FIG. 1 shows one example of a conventional rod pump system of the prior art in a directional or horizontal wellbore. As set out in FIG. 1, tubing 1, which contains pumped liquids 13 is mounted inside a casing 6. A pump 5 is connected at the end of tubing 1 nearest the reservoir 9. Sucker rods 11 are connected from the top of pump 5 and continue vertically to the surface 12. Casing 6, cylindrical in shape, surrounds and is coaxial with tubing 1 and extends below tubing 1 and pump 5 on one end and extends vertically to surface 12 on the other end. Below casing 6 is curve 8 and lateral 10 which is drilled through reservoir 9. The process is as follows: reservoir fluids 7 are produced from reservoir 9 and enter lateral 10, rise up curve 8 and casing 6. Because reservoir fluids 7 are usually multiphase, it separates into annular gas 4 and liquids 17. Annular gas 4 emanates from reservoir fluids 7 and rises in annulus 2, which is the void space formed between tubing 1 and casing 6. The annular gas 4 continues to rise up annulus 2 and then flows out of the well to the surface 12. Liquids 17 enter pump 5 by the force of gravity from the weight of liquids 17 above pump 5 and enter pump 5 to become pumped liquids 13 which travel up tubing 1 to the surface 12. Pump 5 is not considered to be limiting, but may be any down-hole pump or pumping system, such as a progressive cavity, jet pump, or electric submersible, and the like.

FIG. 2 shows one example of a conventional gas lift system of the prior art in a directional or horizontal wellbore. Referring to FIG. 2, inside the casing 6, is tubing 1 connected to packer 14 and conventional gas lift valve 15. Below casing 6 is curve 8 and lateral 10 which is drilled through reservoir 9. The process is as follows: reservoir fluids 7 from reservoir 9 enter lateral 10 and rise up curve 8 and casing 6 and enter tubing 1. The packer 14 provides pressure isolation which allows annulus 2, which is formed by the void space between casing 6 and tubing 1, to increase in pressure from the injection of injection gas 16. Once the pressure increases sufficiently in annulus 2, the conventional gas lift valve 15 opens and allows the injection gas 16 to pass from the annulus 2 into the tubing 1, which then commingles with the reservoir fluids 7 to become gas lifted liquids 13. This lightens the fluid column and the gas lifted liquids 13 rise up the tubing 1 and then flow out of the well to the surface 12.

FIG. 3 shows the preferred embodiment of the invention utilizing a downhole pump and a gas lift system in a horizontal or deviated wellbore. Referring to FIG. 3, inside casing 6, is tubing 1 which begins at the surface 12 and contains internal gas lift valve 15, bushing 25, and inner concentric tubing 21. Tubing 1 is sealingly engaged to packer 14. Tubing 1 and inner concentric tubing 21, extend below packer 14 through curve 8 and into lateral 10, which is drilled though reservoir 9. Inside casing 6 and adjacent to tubing 1 is tubing 3 which contains pump 5 and sucker rods 11. Tubing 3 is not sealingly engaged to packer 14. The process is as follows: reservoir fluids 7 enter lateral 10 and rise up curve 8 and enter tubing 1. The reservoir fluids 7 are commingled with injection gas 16 to become commingled fluids 18 which rise up chamber annulus 19, which is the void space formed between inner concentric tubing 21 and tubing 1. The commingled fluids 18 then exit through holes in perforated sub 24. Annular gas 4 separates from commingled fluids 18 and rise in annulus 2, which is formed by the void space between casing 6 and tubing 1 and tubing 3. Annular gas 4 then enters flowline 30 at the surface 12 and enters compressor 38 to become compressed gas 33, and travels through flowline 31 to surface tank 34. The compressor 38 is not considered to be limiting, in that it is not crucial to the design if another source of pressured gas is available, such as pressured gas from a pipeline. Compressed gas 33 then travels through flowline 32 which is connected to actuated valve 35. This actuated valve 35 opens and closes depending on either time or pressure realized in surface tank 34. When actuated valve 35 opens, compressed gas 33 flows through actuated valve 35 and travels through flowline 32 and into tubing 1 to become injection gas 16. The injection gas 16 travels down tubing 1 to internal gas lift valve 15, which is normally closed thereby preventing the flow of injection gas 16 down tubing 1. A sufficiently high pressure in tubing 1 above internal gas lift valve 15 opens internal gas lift valve 15 and allows the passage of injection gas 16 through internal gas lift valve 15. The injection gas 16 then enters the inner concentric tubing 21, and eventually commingles with reservoir fluids 7 to become commingled fluids 18, and the process begins again. The liquids 17 separate from the commingled fluids 18 and fall in annulus 2 and are trapped above packer 14. As more liquids 17 are added to the annulus 2, liquids 17 rise above and are gravity fed into pump 5 to become pumped liquids 13 which travel up tubing 3 to the surface 12.

FIG. 4 shows an alternate embodiment of the invention similar to the design in FIG. 3 except that it does not utilize the internal gas lift valve 15.

FIG. 5 shows yet another alternate embodiment of the invention utilizing a downhole pump and a gas lift system in a horizontal or deviated wellbore with a different downhole configuration from FIG. 3. Referring to FIG. 5, inside the casing 6, is tubing 1 which contains an internal gas lift valve 15 and is sealingly engaged to packer 14. Packer 14 is preferably a dual packer assembly and is connected to Y block 18 which in turn is connected to chamber outer tubing 20. Chamber outer tubing 20 continues below casing 6 through curve 8 and into lateral 10 which is drilled through reservoir 9. Inner concentric tubing 21 is secured by chamber bushing 22 to one of the tubular members of Y Block 18 leading to lower tubing section 37. The inner concentric tubing 21 extends inside of Y block 18 and outer chamber tubing 20 through the curve 8 and into the lateral 10. The second tubing string arrangement comprises a lower section 37 and an upper section 36. The lower section 37 comprises a perforated sub 24 connected above standing valve 23 and is then sealingly engaged in the packer 14. Perforated sub 24 is closed at its upper end and is connected to the upper tubing section 36. Upper tubing section 36 comprises a gas shroud 28, a perforated inner tubular member 27, a cross over sub 29 and tubing 3 which contains pump 5 and sucker rods 11. The gas shroud 28 is tubular in shape and is closed at its lower end and open at its upper end. It surrounds perforated inner tubular member 27, which extends above gas shroud 28 to crossover sub 29 and connects to the tubing 3, which continues to the surface 12. Above the crossover sub 29, and contained inside of tubing 3 at its lower end, is pump 5 which is connected to sucker rods 11, which continue to the surface 12. Annular gas 4 travels up annulus 2 into flow-line 30 which is connected to compressor 38 which compresses annular gas 4 to become compressed gas 33. The compressor 38 is not considered to be limiting, in that it is not crucial to the design if another source of pressured gas is available, such as pressured gas from a pipeline. Compressed gas 33 flows through flow-line 31 to surface tank 34 which is connected to a second flowline 32 that is connected to actuated valve 35. This actuated valve 35 opens and closes depending on either time or pressure realized in surface tank 34. When actuated valve 35 opens, compressed gas 33 flows through actuated valve 35 and travels through flowline 32 and into tubing 1 to become injection gas 16. The injection gas 16 travels down tubing 1 to internal gas lift valve 15, which is normally closed thereby preventing the flow of injection gas 16 down tubing 1. A sufficiently high pressure in tubing 1 above internal gas lift valve 15 opens internal gas lift valve 15 and allows the passage of injection gas 16 through internal gas lift valve 15, through Y Block 18 and into chamber annulus 19, which is the void space between inner concentric tubing 21 and chamber outer tubing 20. Injection gas 16 is forced to flow down chamber annulus 19 since its upper end is isolated by chamber bushing 22. Injection gas 16 displaces the reservoir fluids 7 to become commingled fluids 18 which travel up the inner concentric tubing 21. Commingled fluids 18 travel out of inner concentric tubing 21 into one of the tubular members of Y Block 18, through packer 14 and standing valve 23, and then through the perforated sub 24 into annulus 2, where the gas separates and rises to become annular gas 4 to continue the cycle. The liquids 17 separate from the commingled fluids 18 and fall by the force of gravity and are trapped in annulus 2 above packer 14 and are prevented from flowing back into perforated sub 24 because of standing valve 23. As liquids 17 accumulate in annulus 2, they rise above pump 5 and are forced by gravity to enter inside of gas shroud 28 and into perforated sub 26 where they travel up inner tubular member 27 and cross-over sub 29 to enter pump 5 where they become pumped liquids 13 and are pumped up tubing 3 to the surface 12.

FIG. 6 shows an alternate embodiment of the invention similar to the design in FIG. 5 except that it does not utilize the internal gas lift valve 15.

As can be seen from the foregoing description of the preferred and alternate embodiments, the present invention is intended to provide an artificial lift system. Because many varying and difference embodiments may be made within the scope of the invention concept taught herein which may involve many modifications in the embodiments herein detailed in accordance with the descriptive requirements of the law, it is to be understood that the details herein are to be interpreted as illustrative and not in a limiting sense. 

1. An artificial lift system for use in a wellbore extending to the surface and having reservoir fluids and a wellbore section that is deviated from vertical and a pressured gas source, comprising: a gas lift system; a packer; a downhole assembly having a downhole pump adapted to pump reservoir fluids; a plurality of tubing string arrangements; a casing having said packer mounted therein, said casing surrounding said plurality of tubing string arrangements in the wellbore, wherein there is included a first tubing string being sealingly engaged to said packer and providing a conduit for the pressured gas to operate said gas lift system to lift the reservoir fluids from below said packer to above said packer, and a second tubing string which houses said downhole pump and provides a conduit for pumping the reservoir fluids above said packer to the surface.
 2. The artificial lift system of claim 1, wherein said gas lift system includes a gas flowline connected to said first tubing string, and the source of the pressured gas connects to a surface tank and said gas flowline contains a valve controlling the passage of the pressured gas into said first tubing string.
 3. The artificial lift system of claim 1, wherein said first tubing string contains at least one inner concentric tubing string.
 4. The artificial lift system of claim 3, wherein the annulus between said concentric tubing strings at the upper end is isolated above and below said concentric tubing strings.
 5. The artificial lift system of claim 3, wherein said first tubing string and said inner concentric tubing string extend through said packer and said inner concentric tubing string is in fluid communication with said annulus of said concentric tubing strings at their lower ends.
 6. The artificial lift system of claim 3, wherein said first tubing string further contains a perforated sub above said packer below the point where said inner concentric tubing is connected and isolated from said first tubing string.
 7. The artificial lift system of claim 1, wherein said first tubing string further includes an internal gas lift valve.
 8. The artificial lift system of claim 1, wherein said second tubing string contains said downhole pump.
 9. The artificial lift system of claim 1, wherein there is included a compressor system connected to said gas lift system to introduce the pressured gas to said first tubing string.
 10. An artificial lift system for use in a wellbore extending to the surface having reservoir fluids and a wellbore section that is deviated from vertical and a pressured gas source, comprising: a gas lift system responsive to the pressured gas source; a packer; a downhole assembly having a downhole pump adapted to pump downhole fluids; a plurality of tubing string arrangements; a casing surrounding said plurality of tubing string arrangements in the wellbore, wherein there is included a first tubing string arrangement, said first tubing string arrangement providing a conduit for the pressured gas to operate said gas lift system, and a second tubing string having an upper section and a lower section, said upper section housing said downhole pump and providing conduit for the pumped the reservoir fluids and said lower section being fluid isolated from said upper section, said lower section sealingly engaged to said packer and providing conduit for removal of the reservoir fluids from below said packer to above said packer.
 11. The artificial lift system of claim 10, wherein there is further included a concentric tubing string arrangement with a Y block, said first and second tubing string arrangements being connected to said concentric tubing string arrangement with said Y block.
 12. The artificial lift system of claim 10, wherein there is included a Y Block and said tubing string arrangements below said Y Block are concentric and said concentric tubing strings comprise an inner concentric tubing and an outer concentric tubing.
 13. The artificial lift system of claim 12, wherein the annulus between the concentric tubing strings at the upper end of said Y Block is isolated above and below said concentric tubing strings and the bottom of said inner concentric tubing string is in fluid communication with said annulus of said concentric tubing strings.
 14. The artificial lift system of claim 10, wherein said first tubing string arrangement further includes an internal gas lift valve.
 15. The artificial lift system of claim 10, wherein said first tubing string arrangement is connected to a gas flowline including a valve that controls the passage of the pressured gas into said first tubing string and a surface tank connected to a compressor, connected to a gas flowline, connected to the annulus of the wellbore. Said annulus is formed by the void space between said casing and said plurality of tubing string arrangements.
 16. The artificial lift system of claim 10, wherein there is a perforated sub and a standing valve mounted in the lower section of said second tubing string above said packer, and said perforated sub is mounted above said standing valve where said standing valve is oriented to prevent the flow of the reservoir fluids from above said standing valve to below said standing valve.
 17. The artificial lift system of claim 16, wherein there is included a gas shroud mounted above said perforated sub, and said gas shroud having an open upper end and a closed lower end.
 18. The artificial lift system of claim 17 wherein said gas shroud surrounds a perforated inner tubular member.
 19. An artificial lift system for use in a wellbore extending to the surface and having reservoir fluids and a wellbore section that is deviated from vertical and a pressured gas source, comprising: a gas lift system; a packer; a downhole assembly having a downhole pump adapted to pump reservoir fluids; a plurality of tubing string arrangements extending into the deviated section.
 20. The artificial lift system of claim 19, wherein said gas lift system is operated intermittently.
 21. The artificial lift system of claim 10, wherein said gas lift system is operated intermittently.
 22. The artificial lift system of claim 1, wherein said gas lift system in operated intermittently. 